DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 

BART Analysis for 

Reid Gardner Station Unit 3 

Prepared for 

NV Energy 

6226 West Sahara Avenue 

Las Vegas, NV 89031 

Revised Report 

October 2008 

Prepared By: 

2285 Corporate Circle 

Henderson, NV 89074 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC ES-1 

Executive Summary 

Background 

In response to the Regional Haze Rule and Best Available Retrofit Technology (BART) 

regulations and guidelines, CH2M HILL was requested to perform a BART analysis for NV 

Energy Reid Gardner Station Unit 3 (hereafter referred to as Reid Gardner 3). A BART 

analysis has been conducted for the following criteria pollutants: oxides of nitrogen (NOx), 

sulfur dioxide (SO2), and particulate matter less than 10 microns in aerodynamic diameter 

(PM10). The Reid Gardner Station consists of four units: three nominal 100-megawatt (MW) 

units and one nominal 265-MW unit, for a total station nominal generating capacity of 

565 MW. Only units 1 through 3 are BART-eligible. BART must be implemented within 

5 years after the State Implementation Plan (SIP) is approved by the United States 

Environmental Protection Agency (EPA). A compliance date of 2015 was assumed for this 

analysis. 

In completing the BART analysis, technology alternatives were investigated, and potential 

reductions in NOx, SO2, and PM10 emission rates were identified. While expected emissions 

levels for each pollutant were estimated, comparisons with the proposed NV Energy BART 

Limits for NOx, SO2, and PM10 are also presented. Listed below by pollutant are the 

technology alternatives that were investigated: 

NOx emission controls: 

• Low NOx Burners (LNB) with Overfire Air (OFA) 

• Low NOx Burner (LNB) with selective non-catalytic reduction system (SNCR) 

• Rotating Opposed Fire Air (ROFA) with Rotamix 

• LNB with selective catalytic reduction (SCR) system 

• ROFA with SCR 

SO2 emission controls: 

• Dry flue gas desulfurization (FGD) system 

• Dry sorbent injection 

• Furnace sorbent injection 

• New wet FGD system 

• Improve or upgrade wet soda ash FGD system operation 

PM10 emission controls: 

• Upgrade mechanical collector 

• Electrostatic precipitator (ESP) 

• Fabric filter 
EXECUTIVE SUMMARY 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC ES-2 

BART Engineering Analysis 

The specific steps in a BART engineering analysis are identified in the Code of Federal 

Regulations (CFR) at 40 CFR 51 Appendix Y, Section IV. The evaluation must include the 

following: 

1. The identification of available, technically feasible, retrofit control options 

2. Consideration of any pollution control equipment in use at the source (which affects the 

availability of options and their impacts) 

3. The costs of compliance with the control options 

4. The remaining useful life of the facility 

5. The energy and non-air quality environmental impacts of compliance 

6. The degree of visibility improvement that may reasonably be anticipated from the use of 

BART 

These steps are incorporated into the BART analysis: 

Step 1 – Identify All Available Retrofit Control Technologies 

Step 2 – Eliminate Technically Infeasible Options 

• The identification of available, technically feasible, retrofit control options 

• Consideration of any pollution control equipment in use at the source (which affects the 

applicability of options and their impacts) 

Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

• Costs associated with control technologies are summarized in the economic analysis 

presented in Appendix A. For clarity, Appendix A also includes sample economic 

analysis spreadsheet calculations and explanation of assumptions used.

Step 4 – Evaluate Energy and Non-Air Quality Impacts 

• The costs of compliance with the control options 

• The remaining useful life of the facility 

• The energy and non-air quality environmental impacts of compliance 

Step 5 – Evaluate Visibility Impacts 

• The degree of visibility improvement that may reasonably be anticipated from the use of 

BART 

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. All costs 

included in the BART analyses are in 2007 dollars, and costs have not been escalated to the 

assumed 2015 BART implementation date. 
EXECUTIVE SUMMARY 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC ES-3 

Establishing Emission Reduction Levels from BART Analysis Results 

As an integral part of the BART analysis process, control cost and expected emission 

information was developed for NOx, SO2, and PM10. This information is assembled from 

various sources including emission reduction equipment vendors, NV Energy operating 

and engineering data, and internal CH2M HILL historical information. 

The level of accuracy of the cost estimate can be broadly classified as American Association 

of Cost Engineers (AACE) Class V or “Order of Magnitude,” which can be categorized as 

+50 percent/-30 percent. There are several reasons for selecting this range of cost estimates 

to be included in the BART analysis. They are primarily a result of the difficulty in receiving 

detailed and accurate information from equipment vendors based on limited available data 

provided to the vendors. Because of the active power industry marketplace, obtaining 

engineering and construction information is restricted due to vendor workload. Material 

and construction labor costs also change rapidly in today’s active economy. However, this 

level of cost estimate precision is adequate for comparison of control technology 

alternatives. The accuracy of expected emissions may also be questionable, and is also 

attributable to the inability to gain timely and accurate vendor information. This is 

exemplified by the difficulty in obtaining background information, and the vendor time 

required to develop accurate emission projections for study purposes in comparison to their 

response to actual project request for proposals. Also, variance in expected emissions can be 

dependent upon the pollutant under consideration (i.e., particulate emissions can generally 

be more accurately predicted than NOx emissions). Therefore, when establishing emission 

limitations in permits, consideration of variability in cost and expected emissions 

information must be considered. 

Coal Characteristics 

The source of fuel burned at Reid Gardner Unit 3 is primarily western bituminous coal. 

Natural gas will be utilized during startup, shutdown, and flame stabilization. 

Recommendations 

NOx Emission Control 

LNB with OFA has been selected as the NOx reduction technology with a NV Energy BART 

Limit (NVEBL) of 0.39 lb/MMBtu averaged on an annual basis. There is significant 

uncertainty involved in obtaining vendor emission guarantees and associated 

equipment/construction costs at this stage of analysis when retrofitting older boiler units. 

Site specific engineering is required on a “unit by unit” basis to determine the most effective 

control technology. 

Due to uncertainties in future coal supply, and changes in boiler operation from the current 

pressurized operation to balanced draft operation, the NVEBL of 0.39 lb/MMBtu on an 

annual basis was established. 
EXECUTIVE SUMMARY 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC ES-4 

SO2 Emission Control 

The utilization of the existing wet soda ash FGD system is BART for Reid Gardner 3 with an 

NV Energy BART Limit (NVEBL) of 0.40 lb/MMBtu averaged on a 24-hour basis. 

PM10 Emission Control 

BART for Reid Gardner 3 will be accomplished by the installation of a fabric filter with an 

NV Energy BART Limit (NVEBL) of 0.02 lb/MMBtu averaged on a 3-hour basis, which is 

currently planned for installation by July 1, 2010. No further PM10 emission control will be 

required to achieve BART. 

Control Recommendation 

The BART selections include the utilization of LNB and OFA, continued FGD system 

operation, and installing a fabric filter for Reid Gardner 3. These selections are supported by 

cost and visibility analyses. Even though the NVEBL for each pollutant was established 

utilizing technology specific estimated design values, NVE maintains the flexibility to meet 

the limit by implementing operational or technology options of their choice BART Modeling 

Analysis. 

CH2M HILL is using the CALPUFF modeling system to assess the visibility impacts of 

emissions from Reid Gardner 3 at nearby Class I areas. The Class I areas potentially affected 

are located more than 50 kilometers (km), but less than 300 km, from the Reid Gardner 

Station. 

The Class I areas include the following national parks (NP) and wilderness areas (WA): 

• Bryce Canyon NP 

• Grand Canyon NP 

• Joshua Tree NP 

• Sycamore Canyon WA 

• Zion NP 

Visibility impacts were determined for the 1) WRAP baseline, 2) the current Title V emission 

permit limits, and 3) the proposed NV Energy BART Limits (NVEBL). 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC ii 

Contents 

Section Page 

Executive Summary...................................................................................................................... ES-1

Background ........................................................................................................................ES-1

BART Engineering Analysis ............................................................................................ES-2

Coal Characteristics...........................................................................................................ES-3

Recommendations.............................................................................................................ES-3

NOx Emission Control .........................................................................................ES-3

SO2 Emission Control...........................................................................................ES-4

PM10 Emission Control ........................................................................................ES-4

Control Recommendation ...................................................................................ES-4

Contents................................................................................................................................................ii

Acronyms and Abbreviations .........................................................................................................iv

1.0 Introduction.......................................................................................................................... 1-1

1.1 Purpose...................................................................................................................... 1-1

2.0 Present Unit Operation....................................................................................................... 2-1

3.0 BART Engineering Analysis ............................................................................................. 3-1

3.1 Applicability ............................................................................................................. 3-1

3.2 BART Process............................................................................................................ 3-1

3.2.1 BART NOx Analysis .................................................................................. 3-2

3.2.2 BART SO2 Analysis ................................................................................. 3-10

3.2.3 BART PM10 Analysis ............................................................................... 3-13

4.0 BART Modeling Analysis.................................................................................................. 4-1

4.1 Introduction .............................................................................................................. 4-1

4.2 Model Selection ........................................................................................................ 4-1

4.3 CALMET Methodology........................................................................................... 4-2

4.3.1 Dimensions of the Modeling Domain .................................................... 4-2

4.3.2 CALMET Input Data................................................................................. 4-4

4.3.3 Validation of CALMET Wind Field........................................................ 4-5

4.4 CALPUFF Methodology ......................................................................................... 4-6

4.4.1 CALPUFF Modeling ................................................................................. 4-6

4.4.2 Receptor Grids and Coordinate Conversion ......................................... 4-7

4.5 Visibility Post-processing........................................................................................ 4-7

4.5.1 CALPOST ................................................................................................... 4-7

4.6 Results........................................................................................................................ 4-8

4.6.1 WRAP Verification Runs Results............................................................ 4-8

4.6.2 BART Modeling Analysis......................................................................... 4-9

5.0 BART Analysis and Recommendations.......................................................................... 5-1

5.1 Recommended BART Controls.............................................................................. 5-1

5.2 Dispersion Modeling Results ................................................................................. 5-2

NOx Control Scenario Visibility Modeling ......................................................... 5-4

5.3 Recommendations.................................................................................................... 5-5

5.3.1 NOx Emission Control .............................................................................. 5-5
CONTENTS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC iii 

5.3.2 SO2 Emission Control................................................................................ 5-5

5.3.3 PM10 Emission Control.............................................................................. 5-6

5.4 Just-Noticeable Differences in Atmospheric Haze.............................................. 5-6

6.0 References............................................................................................................................. 6-1

Appendices 

A Economic Analysis 

B BART Protocol 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC iv 

Acronyms and Abbreviations 

ACFM actual cubic feet per minute 

AQRV air quality related value 

ASOS Automated Surface Observing System 

BACT Best Available Control Technology 

BART Best Available Retrofit Technology 

Btu British thermal unit 

CalDESK Program to display data and results 

CALMET Meteorological data preprocessing program for CALPUFF 

CALPOST Post-processing program for calculating visibility impacts 

CALPUFF Gaussian puff dispersion model 

CaSO4 calcium sulfate 

CDPHE Colorado Department of Health and Environment 

CFR Code of Federal Regulations 

CO carbon monoxide 

CTG Composite Theme Grid 

DBA dibasic acid 

∆dV delta deciview, change in deciview 

DEM digital elevation model 

dV deciview 

EC elemental carbon 

EPA United States Environmental Protection Agency 

ESP electrostatic precipitator 

f (RH) relative humidity factor 

FDDA Four Dimensional Data Assimilation 

FGD flue gas desulfurization 

FLM Federal Land Manager 

ft./sec. feet per second 
ACRONYMS AND ABBREVIATIONS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC v 

Fuel NOx oxidation of fuel bound nitrogen 

HHV higher heating value 

hp horsepower 

km kilometer 

kW kilowatt 

kW-Hr kilowatt-hour 

LAER lowest achievable emission rate 

lb/MMBtu pounds per million British thermal unit 

LCC Lambert Conformal Conic 

LNB low-NOx burner 

LOI loss on ignition 

MM5 Mesoscale Meteorological Model, Version 5 

MMBtu million British thermal unit 

MSL mean sea level 

MW megawatt 

N2 nitrogen 

NCDC National Climatic Data Center 

NDEP Nevada Division of Environmental Protection 

NO nitric oxide 

NOAA National Oceanic and Atmospheric Administration 

NOx oxides of nitrogen 

NP National Park 

NPS National Park Service 

NSR New Source Review 

NVE NV Energy 

NWS National Weather Service 

OFA over-fire air 

O&M operations and maintenance 

PM2.5 particulate matter less than 2.5 microns in aerodynamic diameter 

PM10 particulate matter less than 10 microns in aerodynamic diameter 
ACRONYMS AND ABBREVIATIONS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC vi 

ppb part per billion 

PPM parts per million 

PRB Powder River Basin 

RMC Regional Modeling Center 

ROFA Rotating Opposed Fire Air 

S&L Sargent & Lundy 

NVEBL NV Energy BART Limit 

SCR selective catalytic reduction 

SIP State Implementation Plan 

SNCR selective non-catalytic reduction 

SO2 sulfur dioxide 

SO4 sulfates 

sq. ft. square feet 

USGS U.S. Geological Survey 

WA Wilderness Area 

WRAP Western Regional Air Partnership 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 1-1 

1.0 Introduction 

1.1 Purpose 

Best Available Retrofit Technology (BART) guidelines were established as a result of United 

States Environmental Protection Agency (EPA) regulations intended to reduce the 

occurrence of regional haze in national parks and other Class I protected air quality areas in 

the United States1. These guidelines provide guidance for states when determining which 

facilities must install additional controls, and the type of controls that must be used. 

Facilities eligible for BART installation were built between 1962 and 1977 and have the 

potential to emit more than 250 tons/year of visibility-impairing pollutants. 

The State of Nevada has identified those eligible in-state facilities that are required to reduce 

emissions under BART and will set BART emissions limits for those facilities. This 

information will be included in the Nevada State Implementation Plan (SIP), which the State 

has estimated will be formally submitted to the EPA by December 1, 2008. The EPA BART 

guidelines also state that the BART emission limits must be fully implemented within 

5 years of EPA’s approval of the SIP. 

There are five basic elements related to BART, when addressing the issue of emissions for 

the identified facilities: 

• Any existing pollution control technology in use at the source 

• The cost of the controls 

• The remaining useful life of the source 

• The energy and non-air environmental impacts of compliance

• The degree of improvement in visibility that may reasonably be anticipated from the use 

of such technology 

This report documents the BART analysis that was performed on the Reid Gardner Station 

Unit 3 (hereafter referred to as Reid Gardner 3) by CH2M HILL for NV Energy. The analysis 

was performed for the pollutants oxides of nitrogen (NOx), sulfur dioxide (SO2), and 

particulate matter less than 10 microns in aerodynamic diameter (PM10) because they are the 

primary criteria pollutants that affect visibility. 

Section 2.0 of this report provides a description of the present unit operation, including a 

discussion of coal sources and characteristics. The BART Engineering Analysis is provided 

in Section 3.0 by pollutant type. Section 4.0 provides the BART modeling methodology and 

Section 5.0 discusses the BART analysis and recommendations. References are provided in 

Section 6.0. Appendices A and B provide supporting information on the economic analysis 

and the BART modeling protocol. 

 

1 40 Code of Federal Regulations (CFR) Part 51: Regional Haze Regulations and Guidelines for Best Available Retrofit 

Technology (BART) Determinations; Final Rule. 70 Federal Register, 39103-39172, July 6, 2005. 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 2-1 

2.0 Present Unit Operation 

The Reid Gardner Station consists of four units: three nominal 100-megawatt (MW) units 

and one nominal 265-MW unit, for a total nominal generating capacity of 565 MW. Reid 

Gardner 4 is not a BART-eligible unit. Reid Gardner 3 is a nominal 100-MW output unit 

commissioned in 1965 and is located in Moapa, Nevada. Unit 3 is currently equipped with a 

wall-fired pulverized coal boiler manufactured by Foster Wheeler with low-NOx burners 

(LNB) and over-fire air (OFA), mechanical collector for particulate control, and a 

venturi/tray scrubber that uses soda ash for SO2 removal. 

A unit upgrade project is currently in progress on Reid Gardner 3 and consists of the 

following scope: 

• Installation of a pulse jet fabric filter 

• Installation of a new fly ash handling system 

• Removal of existing mechanical collector 

This pulse jet fabric filter is scheduled for completion by July 2010; therefore this BART 

analysis assumes that the above scope and equipment will be implemented. However, for 

purposes of this analysis, the costs and emissions reduction for the fabric filter are included 

in the analysis. For Table 2-1 below, the PM10 emission rate shown is equal to the fabric filter 

vendor guarantee. 

Reid Gardner 3 was placed in service in 1976 and this analysis is based on a 20-year life for 

BART control technologies. Assuming a BART implementation date of 2015, this will result 

in an approximate remaining useful life for Reid Gardner 3 of 20 years from the installation 

date of any BART-related equipment. However, this report does not attempt to quantify any 

additional life extension beyond current plans or costs needed to allow the unit and these 

control devices at Reid Gardner 3 to operate until 2035. 

The BART regulations state that the baseline emissions utilized for visibility modeling be 

established by identifying the highest 24-hour average actual emission rate from the period 

modeled for the pre-control scenario. Modeling would then consider the expected emissions 

rate after the installation of BART controls to establish the level of visibility improvement. 

For the pre-control scenario, modeling was conducted at the WRAP 24-hour maximum 

values and at the Title V permit limits for the unit. The post-control scenario was modeled at 

the proposed NV Energy BART Limits (discussed in Sections 3, 4 and 5, with the exception 

of the NOx and PM10 emission rates which is higher than the NVEBL. 

Table 2-1 lists additional unit information and study assumptions for this analysis. 
SECTION 2.0: PRESENT UNIT OPERATION 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 2-2 

TABLE 2-1 

Unit Operation and Study Assumptions 

Reid Gardner 3 

General Plant Data 

Site Elevation (feet above MSL) 1,570 

Stack Height (feet) 270 

Stack Exit ID (feet)/Exit Area (sq. ft.) 12.9/130.7

Stack Exit Temperature (°F) 151 

Stack Exit Velocity (ft./sec.) 71.4 

Stack Flow (ACFM) 559,911 

Annual Unit Capacity Factor (percent) 91 

Net Unit Output (Nominal MW) 100 

Net Unit Heat Rate (Btu/kW-Hr)(100 percent load) 11,351 

Boiler Heat Input (MMBtu/Hr)(100% load) 1,237 

Type of Boiler Wall-fired 

Boiler Fuel Bituminous Coal (Primary) 

Natural Gas (Startup, Shutdown, 

Flame Stabilization) 

Coal Sources See Table 2-2 

NOx Emissions Data (24-hour Average Maximum) 

Current NOx Controls LNBs with OFA 

Title V NOx Permit Limit (lb/MMBtu) 0.46 

WRAP NOx Emission Rate (lb/MMBtu) 0.592 

Average NOx Emission Rate (lb/MMBtu)b 0.321 

Maximum NOx Emission Rate (lb/MMBtu)d 0.579 

SO2 Emissions Data (24-hour Average Maximum) 

Current SO2 Controls Soda Ash FGD 

Title V SO2 Permit Limit (lb/MMBtu) 0.55 

WRAP SO2 Emission Rate (lb/MMBtu) 0.320 

Average SO2 Emission Rate (lb/MMBtu)c 0.050 

Maximum SO2 Emission Rate (lb/MMBtu)d 0.290 

PM10 Emissions Data (24-hour Average Maximum)

Current PM10 ControlsaFabric filter 

Title V PM10 Permit Limit (lb/MMBtu) 0.1 

WRAP PM10 Emission Rate (lb/MMBtu) 0.040 

Average PM10 Emission Rate (lb/MMBtu)a 0.015 

a

 After completion of fabric filter installation. 

b

 Used 2004 annual averages. 

c

 Used an average of the 2004 annual averages for Reid Gardner 1, 2, & 3. 

d

 Maximum emission rate as per evaluation of the EPA Acid Rain Database for 2001 through 2003. 

The primary source of fuel burned at Reid Gardner 3 is western bituminous coal. Coal 

sources and characteristics are summarized in Table 2-2. 
SECTION 2.0: PRESENT UNIT OPERATION 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 2-3 

TABLE 2-2 

Coal Sources and Characteristics 

Reid Gardner 3 

Mines Bowie Skyline Sufco Dugout Aberdeen Crandall West Ridge 

Moist. % 8.50 9.79 9.69 5.53 6.83 7.50 5.78 

Ash % 9.06 7.64 7.97 8.65 8.50 8.00 7.48 

Volatile 

Matter % 

33.53 38.20 35.95 33.05 38.00 41.05 34.91 

Fixed 

Carbon % 

48.91 44.37 46.39 52.77 46.16 43.00 51.84 

Sulfur % 0.46 0.57 0.29 0.51 0.51 0.45 1.35 

HHV, 

Btu/lb 

12,012 11,712 11,463 12,469 12,276 12,400 12,856 

Data from report done by NV Energy January 18, 2007, Fly Ash Conveyor System – Units 1, 2 and 3. 

CH2M HILL based inlet SO2 calculations on coal from the Skyline mine since it exhibits the highest sulfur content 

with the exception of West Ridge (not considered typical). 

HHV = higher heating value 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-1 

3.0 BART Engineering Analysis 

3.1 Applicability 

In compliance with regional haze requirements, the State of Nevada must prepare and 

submit visibility SIPs to the EPA for Class I areas. The State has estimated that the formal 

submittal of the SIPs to EPA will occur by December 1, 2008. The first phase of the regional 

haze program is the implementation of BART emission controls on all BART eligible units 

within 5 years after EPA approval of the SIP. 

3.2 BART Process 

The specific steps in a BART engineering analysis are identified in the Code of Federal 

Regulations (CFR) at 40 CFR 51 Appendix Y, Section IV. The evaluation must include the 

following: 

1. The identification of available, technically feasible, retrofit control options 

2. Consideration of any pollution control equipment in use at the source (which affects the 

availability of options and their impacts) 

3. The costs of compliance with the control options 

4. The remaining useful life of the facility 

5. The energy and non-air quality environmental impacts of compliance 

6. The degree of visibility improvement that may reasonably be anticipated from the use of 

BART 

These steps are incorporated into the BART analysis as follows: 

Step 1 – Identify All Available Retrofit Control Technologies 

Step 2 – Eliminate Technically Infeasible Options 

• The identification of available, technically feasible, retrofit control options 

• Consideration of any pollution control equipment in use at the source (which affects the 

applicability of options and their impacts) 

Step 3 – Evaluate Control Effectiveness of Remaining Control Technologies 

• Costs associated with control technologies are summarized in the economic analysis 

presented in Appendix A. For clarity, Appendix A also includes sample economic 

analysis spreadsheet calculations and explanation of assumptions used.
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-2 

Step 4 – Evaluate Energy and Non-Air Quality Impacts 

• The costs of compliance with the control options 

• The remaining useful life of the facility 

• The energy and non-air quality environmental impacts of compliance 

Step 5 – Evaluate Visibility Impacts 

• The degree of visibility improvement that may reasonably be anticipated from BART 

use. 

To minimize costs in the BART analysis, consideration was made of any pollution control 

equipment in use at the source, the costs of compliance associated with the control options, 

and the energy and non-air quality environmental impacts of compliance using these 

existing control devices. In some cases, enhancing the performance of the existing control 

equipment was considered. Other scenarios with new control equipment were also 

developed. 

Separate analyses have been conducted for NOx, SO2, and PM10 emissions. All costs 

included in the BART analysis are in 2007 dollars, and costs have not been escalated to the 

assumed 2013 BART implementation date. 

3.2.1 BART NOx Analysis 

NOx formation in coal-fired boilers is a complex process that is dependent on a number of 

variables, including operating conditions, equipment design, and coal characteristics. 

3.2.1.1 Formation of NOx

During coal combustion, NOx is formed in three different ways. The dominant source of 

NOx formation is the oxidation of fuel-bound nitrogen (fuel NOx). During combustion, part 

of the fuel-bound nitrogen is released from the coal with the volatile matter, and part is 

retained in the solid portion (char). The nitrogen chemically bound in the coal is partially 

oxidized to nitrogen oxides (nitric oxide [NO] and nitrogen dioxide [NO2]) and partially 

reduced to molecular nitrogen (N2). A smaller part of NOx formation is due to high 

temperature fixation of atmospheric nitrogen in the combustion air (thermal NOx). A very 

small amount of NOx is called “prompt” NOx. Prompt NOx results from an interaction of 

hydrocarbon radicals, nitrogen, and oxygen. 

In a conventional pulverized coal burner, air is introduced with turbulence to promote good 

mixing of fuel and air, which provides stable combustion. However, not all of the oxygen in 

the air is used for combustion. Some of the oxygen combines with the fuel nitrogen to form 

NOx. 

Coal characteristics directly affect NOx emissions from coal combustion. Coal ranking is a 

means of classifying coals according to their degree of metamorphism in the natural series, 

from lignite to sub-bituminous to bituminous and on to anthracite. Lower rank coals, such 

as the sub-bituminous coals from the Powder River Basin (PRB), produce lower NOx

emissions than do higher rank bituminous coals, due to their higher reactivity and lower 

nitrogen content. The fixed carbon to volatile matter ratio (fuel ratio), coal oxygen content, 

and rank are good relative indices of the reactivity of a coal. Lower rank coals release more 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-3 

organically bound nitrogen earlier in the combustion process than do higher rank 

bituminous coals. When used with LNBs, sub-bituminous coals create a longer time for the 

kinetics to promote more stable molecular nitrogen; hence resulting in lower NOx emissions. 

3.2.1.2 Step 1: Identify All Available Retrofit Control Technologies 

The first step of the BART process is to evaluate NOx control technologies with practical 

potential for application to Reid Gardner 3, including those control technologies identified 

as Best Available Control Technology (BACT) or lowest achievable emission rate (LAER) by 

permitting agencies across the United States. A broad range of information sources has been 

reviewed in an effort to identify potentially applicable emission control technologies. 

Reid Gardner 3 NOx emissions are currently controlled through the use of Foster Wheeler 

LNBs, which were installed in 1999, and OFA. Reid Gardner 3 is a wall-fired boiler, with 

burners arranged in a 4-by-2 (four-high and two-wide) configuration. 

The following potential NOx control technology options were considered: 

• Low NOx Burners (LNB) with Overfire Air (OFA) 

• Low NOx Burner (LNB) with selective non-catalytic reduction system (SNCR) 

• Rotating Opposed Fire Air (ROFA) with Rotamix 

• LNB with selective catalytic reduction (SCR) system 

• ROFA with SCR 

3.2.1.3 Step 2: Eliminate Technically Infeasible Options 

For Reid Gardner 3, a wall-fired configuration burning primarily bituminous coal, technical 

feasibility will primarily be determined by physical constraints, boiler configuration, and on 

the ability to achieve the proposed NV Energy BART Limit of 0.46 lb/MMBtu. 

For this BART analysis, information pertaining to LNB with OFA, ROFA with Rotamix, 

SNCR, and SCR was based on a combination of vendor information, internal CH2M HILL 

information, and the EPA Air Pollution Cost Control Manual. Sources of cost estimates for 

Reid Gardner 3 are listed in Table 3-1, which also summarizes the control technology 

options evaluated in this BART analysis, along with projected NOx emission rates. All 

technologies listed can meet the proposed NVE BART Limit of 0.39 lb/MMBtu. 

It should be noted estimated emissions information from NOx technologies presented 

represent design targets. With a significant potential for variability in emissions due to 

changes in unit operation, a longer averaging period results in a higher probability in 

meeting the permit emissions value. Emissions based on a 24-hour averaging period are not 

directly comparable to emissions targets based on a longer averaging time. 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-4 

TABLE 3-1 

NOx Control Technology Emission Rate Ranking 

Reid Gardner Station Unit 3 

Technology Source of Estimated Emissions Expected Emission Rate 

(lb/MMBtu)c

Current Permit Limit Title V 0.46 

NVE BART Limit NVEBLa 0.39 (Annual) 

Enhancement of the Existing or 

New LNB w/OFA 

Foster Wheeler <0.390 

LNB w/OFA and SNCRb Foster Wheeler, Fuel Tech 0.23 

ROFA w/Rotamix Mobotec 0.20 

LNB w/OFA and SCR Foster Wheeler 0.07 

ROFA w/SCR Mobotec 0.07 

a NVEBL – Based on LNB with OFA information from Foster Wheeler 

b Assumes 25 percent SNCR removal efficiency. 

c All emission rates are treated as expected rather than guaranteed values. 

ROFA = rotating opposed fire air 

SCR = selective catalytic reduction 

SNCR selective non-catalytic reduction 

3.2.1.4 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

Preliminary vendor proposals, such as those used to support portions of this BART analysis, 

may be technically feasible and provide expected or guaranteed emission rates; however, 

they include inherent uncertainties. These proposals are usually prepared in a limited time 

frame, may be based on incomplete information, may contain over-optimistic conclusions, 

and are non-binding. Therefore, emission rate values obtained in such preliminary 

proposals must be qualified, and it must be recognized that contractual guarantees are 

established only after more detailed analysis has been completed. Also, emission rates are 

typically based on a design value (i.e., 30-day rolling average) versus a maximum 24-hour 

value. 

Level of Confidence for Vendor Post-Control Emissions Estimates. To determine the level 

of NOx emissions needed to achieve compliance consistently with an established goal, a 

review of typical NOx emissions from coal-fired generating units was completed. As a result 

of this review, it was noted that NOx emissions can vary around an average emissions level. 

This variance can be attributed to many reasons, including coal characteristics, unit load, 

boiler operation including excess air, boiler slagging, burner equipment condition, coal mill 

fineness, and so forth. 

The steps used for determining a level of confidence for the vendor-expected value are as 

follows: 

1. Establish expected NOx emissions value from vendor. 

2. Evaluate vendor experience and historical basis for meeting expected values. 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-5 

3. Review and evaluate unit physical and operational characteristics and restrictions. The 

fewer variations there are in operations, coal supply, etc., the more predictable and less 

variable the NOx emissions are. 

4. Make adjustments to the expected value. For each technology expected value, there is a 

corresponding potential for actual NOx emissions to vary from this expected value. 

From the vendor information presented, along with anticipated unit operational data, an 

adjustment to the expected value can be made. 

The following subsections describe the control technologies and the control effectiveness 

evaluated in this BART analysis. 

LNBs with OFA System. The mechanism used to lower NOx with LNBs is to stage the 

combustion process and provide a fuel-rich condition initially; this is so oxygen needed for 

combustion is not diverted to combine with nitrogen and form NOx. Fuel-rich conditions 

favor the conversion of fuel nitrogen to N2 instead of NOx. Additional air (or OFA) is then 

introduced downstream in a lower temperature zone to burn out the char. Enhancing the 

existing or installing new LNBs and OFA is considered to be a capital cost, combustion 

technology retrofit that may require boiler water wall tube replacement. 

Neural Net Boiler Controls. Information regarding neural net controls for the boiler was 

received from NeuCo, Inc. While NeuCo offers several neural net products, CombustionOpt 

and SootOpt provide the potential for NOx reduction. NeuCo stated these products can be 

used on most boiler control systems and can be effective even in conjunction with other 

NOx reduction technologies. NeuCo predicts that CombustionOpt can reduce NOx by 15 

percent, and SootOpt can provide an additional 5 to 10 percent. Because NeuCo does not 

offer guarantees on this projected emission reduction, a nominal reduction of 15 percent was 

assumed for evaluation purposes. The budgetary prices for CombustionOpt and SootOpt 

were $150,000 and $175,000, respectively, with an additional $200,000 cost for a process link 

to the unit control system. Because NeuCo does not guarantee NOx reduction, the estimated 

emission reduction levels provided can not be considered as reliable projections. Therefore, 

neural net should be considered as a supplementary or polishing technology, but not on a 

stand-alone basis. 

ROFA. Mobotec markets ROFA as an improved second-generation OFA system. Mobotec 

states that the flue gas volume of the furnace is set in rotation by asymmetrically placed air 

nozzles. Rotation is reported to prevent laminar flow and improve gas mixing so that the 

entire volume of the furnace can be used more effectively for the combustion process. In 

addition, the swirling action reduces the maximum temperature of the flames and increases 

heat absorption. Mobotec expects that enhanced mixing will also result in reduction in 

hot/cold furnace zones, improved heat absorption and boiler efficiency, and lower carbon 

monoxide (CO) and NOx emissions. 

A typical ROFA installation will have a booster fan(s) to supply the high-velocity air to the 

ROFA boxes. Mobotec proposed one 1,000-horsepower (hp) fan for Reid Gardner 3 located 

at grade, which would provide hot air at all boiler loads. 

Mobotec does not typically provide installation services because they believe that the Owner 

can more cost-effectively contract for these services. However, they did provide a budgetary 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-6 

price for installation labor. Mobotec provides one onsite construction supervisor during 

installation and startup. 

Due to previous experience with ROFA, NVE does not consider ROFA as a stand-alone 

technology option. 

ROFA w/Rotamix. As described above, ROFA is marketed as an improved OFA system. 

Mobotec provided a proposal for their Rotamix SNCR system, which anticipated 12 to 24 

injection ports for Reid Gardner 3. The guaranteed NOx emission rate for the Rotamix 

system, operating in conjunction with ROFA, is 0.20 lb/MMBtu. Ammonia slip is 

guaranteed at 5 parts per million (ppm) with an ammonia/urea flow rate of 70 to 

110 gallons per hour. 

SNCR. Selective non-catalytic reduction is generally used to achieve modest NOx reductions 

on smaller units. With SNCR, an amine-based reagent such as ammonia or urea is injected 

into the furnace within a temperature range of 1,600 degrees Fahrenheit (°F) to 2,100°F, 

where it reduces NOx to nitrogen and water. NOx reductions of up to 60 percent have been 

achieved, although 20 to 40 percent is more realistic for most applications. 

Reagent utilization, which is a measure of the efficiency with which the reagent reduces 

NOx, can range from 20 to 60 percent, depending on the amount of reduction, unit size, 

operating conditions, and allowable ammonia slip. With low-reagent utilization, low 

temperatures, or inadequate mixing, ammonia slip occurs, allowing unreacted ammonia to 

create problems downstream. The ammonia may render fly ash unsalable, react with sulfur 

to foul heat exchange surfaces, and/or create a visible stack plume. Reagent utilization can 

have an impact on economics, with higher levels of NOx reduction generally resulting in 

lower reagent utilization and higher operating cost. Reductions from higher baseline 

concentrations (inlet NOx) are lower in cost per ton, but result in higher operating costs, due 

to greater reagent consumption. 

A budgetary proposal was received from Fuel Tech for their urea-based SNCR system, 

which provides nominally a 25 percent reduction from baseline NOx levels. Fuel Tech 

proposed using 16 injectors located over three boiler levels. 

SCR. SCR works on the same chemical principle as SNCR, but SCR uses a catalyst to 

promote the chemical reaction. Ammonia or urea is injected into the flue-gas stream, where 

it reduces NOx to nitrogen and water. Unlike the high temperatures required for SNCR, in 

SCR the reaction takes place on the surface of a vanadium/titanium-based catalyst at a 

temperature range between 580° F and 750° F. Due to the catalyst, the SCR process is more 

efficient than SNCR and results in lower NOx emissions. The most common type of SCR is 

the high-dust configuration, where the catalyst is located downstream from the boiler 

economizer and upstream of the air heater and any particulate control equipment. In this 

location, the SCR is exposed to the full concentration of fly ash in the flue gas that is leaving 

the boiler. The high-dust configuration is assumed for Reid Gardner 3. In a full-scale SCR, 

the flue ducts are routed to a separate large reactor containing the catalyst. With in-duct 

SCR, the catalyst is located in the existing gas duct, which may be expanded in the area of 

the catalyst to reduce flue gas flow velocity and increase flue gas residence time. Due to the 

higher removal rate, a full-scale SCR was used as the basis for analysis at Reid Gardner 3. 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-7 

As with SNCR, it is generally more cost effective to reduce NOx emission levels as much as 

possible through combustion enhancements than to minimize the catalyst surface area and 

ammonia requirements of the SCR. 

3.2.1.5 Step 4: Evaluate Energy and Non-Air Quality Impacts 

This step involves the consideration of energy, environmental, and economic impacts 

associated with each control technology. The remaining useful life of the plant is also 

considered during the evaluation. 

Energy Impacts. The installation of LNB with OFA is not expected to impact the boiler 

efficiency to a large degree or forced draft fan power usage. Therefore, these technologies 

will not have energy impacts. 

The Mobotec ROFA system requires installation and operation of one 1,000-hp ROFA fan 

(746 kilowatts [kW] total). Fuel Tech provided an estimated auxiliary power requirement of 

343 kW, and the same estimate was used for Rotamix. 

SCR retrofit impacts the existing flue gas fan systems due to the additional pressure drop 

associated with the catalyst, which is typically a 6- to 8-inch water gage increase. 

The energy impacts summarized above are included in the economic analysis presented in 

Appendix A. 

Environmental Impacts. Mobotec has predicted that CO emissions, and unburned carbon in 

the ash, commonly referred to as loss on ignition (LOI), would be the same or lower than 

prior levels for the ROFA system. 

SNCR and SCR installation could impact the salability and disposal of fly ash due to 

ammonia levels and could potentially create a visible stack plume, which may negate other 

visibility improvements. Other environmental impacts involve the storage of ammonia, 

especially if anhydrous ammonia is used, and the transportation of the ammonia to the 

power plant site. 

These environmental impacts have not been quantified in the economic analysis presented 

in Appendix A. 

Economic Impacts. Costs for the LNB with OFA, ROFA with Rotamix, SNCR, and SCR 

were furnished to CH2M HILL through vendor-obtained price and performance quotations. 

A comparison of the technologies on the basis of costs, design control efficiencies, and tons 

of NOx removed is summarized in Table 3-2, and the first year control costs are presented in 

Figure 3-1. 

The complete Economic Analysis is contained in Appendix A. 

3.2.1.6 Step 5: Evaluate Visibility Impacts 

This is presented in Section 4.0, BART Modeling Analysis. 
SECTI

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-8 TABLE 3-2 NOx Control Cost Comparison Reid Gardner Station Unit 3 

Factor LNB w/OFA 

LNB w/OFA & 

SNCR 

ROFA 

w/Rotamix 

LNB w/OF

SCR 

Total Installed Capital Costs $4.4 Million $6.9 Million $7.9 Million $35.0 MillTotal First Year Fixed and Variable O&M Costs $0.1 Million $0.3 Million $0.5 Million $1.0 MilliTotal First Year Annualized Cost $0.6 Million $1.1 Million $1.4 Million $4.7 MilliPower Consumption (MW) - 0.10 0.75 0.66 Annual Power Usage (Million kW-Hr/Yr) - 0.8 5.9 5.3 NOx Design Control Efficiency 6.5% 29.9% 38.3% 78.2% Tons NOx Removed per Year 95 434 556 1,136 First Year Average Control Cost ($/Ton of NOx

Removed) 

5,807 2,493 2,480 4,155 

Incremental Control Cost ($/Ton of NOx Removed) 5,807 1,564 2,433 5,764 O&M = operations and maintenance The incremental control cost for ROFA w/SCR when compared with LNB w/OFA & SCR results in a non number as the two technologies 

removal in tons/year 
SECTI

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-9 FIGURE 3-1 First-Year Control Cost for NOX Air Pollution Control Options 

Reid Gardner Station Unit 3 

0

1,0002,0003,0004,0005,0006,0007,000

LNB w/OFA LNB w/OFA & SNCR ROFA w/Rotamix LNB w/OFA & SCR 

Air Pollution Control Option

Control Cost ($/Ton NOx Removed)

First Year Average Control Cost First Year Incremental Control Cost
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-10 

3.2.2 BART SO2 Analysis 

SO2 forms in the boiler during the combustion process from the oxidation of the sulfur in the 

coal and is primarily dependent on coal sulfur content. The BART analysis for SO2 emissions 

on Reid Gardner 3 is described below. 

3.2.2.1 Step 1: Identify All Available Retrofit Control Technologies 

A broad range of information sources were reviewed to identify potentially applicable 

emission control technologies for SO2 at Reid Gardner 3. This review included control 

technologies identified as BACT or LAER by permitting agencies across the United States. 

The following potential new SO2 control technology options were considered: 

• Dry flue gas desulfurization (FGD) system 

• Dry sorbent injection 

• Furnace sorbent injection 

• New wet lime/limestone FGD system 

Because Reid Gardner currently uses a soda ash scrubber for SO2 reduction and current 

removal efficiency is greater than 50 percent, the EPA BART regulations state that 

cost-effective scrubber upgrades should be considered. Therefore, the following upgrades to 

the existing scrubber were also considered: 

• Eliminate bypass reheat 

• Install liquid distribution rings 

• Install perforated trays 

• Use organic acid additives 

• Improve or upgrade scrubber auxiliary system equipment 

• Redesign spray header or nozzle configuration 

3.2.2.2 Step 2: Eliminate Technically Infeasible Options 

The current soda ash scrubber SO2 emissions average approximately 0.15 lb/MMBtu or less 

and meet a Title V permit limit of 0.55 lb/MMBtu. Assuming an uncontrolled SO2 emission 

level of 0.97 lb/MMBtu, the currently operating soda ash scrubber is achieving a reduction 

of SO2 of up to 95 percent. With the fabric filter installation, the scrubber venturi section will 

be opened further to reduce draft loss through the equipment, and the scrubber operation 

will be improved to primarily remove SO2 in the scrubber vessel. 

Dry FGD System. A lime spray dryer typically injects lime slurry in the top of the absorber 

vessel with a rapidly rotating atomizer wheel. The rapid speed of the atomizer wheel causes 

the lime slurry to separate into very fine droplets that intermix with the flue gas. The SO2 in 

the flue gas reacts with the calcium in the lime slurry to form dry calcium sulfate particles. 

At Reid Gardner 3, this dry particulate matter would be captured downstream in the 

baghouse that is currently being constructed, along with the fly ash. A lime spray dryer 

system typically produces a dry waste product suitable for landfill disposal. 

A dry FGD system is estimated to achieve a maximum of 90 percent SO2 removal at Reid 

Gardner 3. This would result in a controlled SO2 emission rate of 0.054 lb/MMBtu, based on 

an uncontrolled SO2 emission rate of 0.97 lb/MMBtu. Therefore, this option cannot reduce 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-11 

the current soda ash scrubber emissions of 0.05 lb SO2/MMBtu, and is therefore eliminated 

from further analysis. 

Dry Sodium Sorbent Injection. Dry duct injection of sodium materials, such as sodium 

carbonate or sodium bicarbonate, can be used to remove moderate levels of SO2 from flue 

gas. The sorbent is injected dry into the flue gas downstream of the air heater at 

approximately 300oF, and the reacted and unreacted sorbent material and fly ash would be 

collected in the fabric filter. Maximum SO2 removal efficiency for this technology is 

approximately 75 percent, far less than is now being achieved with the soda ash scrubber, 

which eliminates this technology from further consideration. 

Furnace Sorbent Injection. Furnace sorbent injection consists of injecting lime or limestone 

into the boiler above the combustion zone (approximately 2,200oF) or ahead of the 

economizer (approximately 1,100oF). The sorbent reacts with the SO2 in the flue gas to form 

calcium sulfate (CaSO4), and the CaSO4, unreacted sorbent, and fly ash is collected in the 

fabric filter. While furnace sorbent injection is relatively simple, it has a limited SO2 removal 

efficiency limitation of approximately 60 percent. Because this is far less than the current 

soda ash scrubber performance, this option is eliminated from further analysis. 

New Wet Lime/Limestone Scrubber. A typical wet lime/limestone scrubber consists of SO2

laden flue gas entering a scrubber vessel where it is sprayed with a water/calcium slurry. 

The calcium reacts to form calcium sulfite or sulfate, and is then either removed and 

disposed as scrubber waste or reclaimed as gypsum. Wet lime/limestone scrubbers are 

capable of very high SO2 removal efficiencies, with a 95 percent removal efficiency assumed 

for this BART analysis. 

Wet Soda Ash FGD System. Wet soda ash FGD systems operate by treating the flue gas in 

large scrubber vessels with a soda ash solution. The scrubber mixes the flue gas and alkaline 

reagent using a tray arrangement to distribute the reagent across the scrubber vessel. The 

sodium in the reagent reacts with the SO2 in the flue gas to form sodium sulfite and sodium 

bisulfite, which are removed from the scrubber and disposed. 

The wet soda ash FGD system at Reid Gardner 3 currently achieves up to 94 percent SO2

removal, resulting in an average SO2 outlet emission rate of approximately 0.15 lb/MMBtu 

or less. The following scrubber upgrade alternatives were investigated: 

• Eliminate bypass reheat. With the completion of the fabric filter installation, the flue gas 

leaving the scrubber will not be reheated. Therefore, this scrubber upgrade option has 

already been implemented. 

• Install liquid distribution rings. Perforated trays accomplish the same purpose of 

liquid distribution rings, namely better distribution of scrubber liquid. 

• Install perforated trays. Reid Gardner 3 scrubber has distribution sieve trays that allow

the flue gas to bubble through the liquid. With the installation of a new fabric filter for 

improved particulate control ahead of the scrubber, enhanced scrubber operation is 

anticipated due to lessened tray pluggage from fly ash. 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-12 

• Use organic acid additives. Organic acid additives such as dibasic acid (DBA) may be 

used to improve SO2 removal efficiency by increasing scrubbing liquor alkalinity; 

however, any potential improvements in SO2 removal are difficult to predict. Testing 

would be required to demonstrate feasibility and determine any possible impacts. 

• Improve or upgrade scrubber auxiliary system equipment. With the installation of a 

fabric filter, particulate loading into the scrubber will be reduced. This will lessen 

pluggage of the scrubber trays and nozzles with fly ash, which should result in 

improved SO2 removal and greater reliability. 

• Redesign spray header or nozzle configuration. Reduced particulate loading will 

reduce pluggage of scrubber nozzles, which should improve liquid distribution and 

scrubber reliability. 

It is projected that the operation of the present wet soda ash FGD system may be improved 

as a result of the fabric filter installation. However, even with incremental improvements, 

minimal additional improvement to the current low SO2 emission level can be consistently 

expected from upgrades to the existing wet soda ash scrubber. 

Table 3-3 summarizes the control technology options evaluated in this BART analysis, along 

with projected SO2 emission rates. Only scrubber upgrades and new lime/limestone wet 

scrubber technology options can equal or exceed the removal efficiency of the current wet 

soda ash scrubber. Therefore, only these two alternatives are considered technically feasible 

for purposes of this analysis. 

TABLE 3-3 

SO2 Control Technology Emission Rate Ranking 

Reid Gardner Station Unit 3 

Technology 

Projected Emission Rate 

(lb/MMBtu) 

Estimated SO2 Removal 

Efficiency (%) 

Current Permit Level 0.55 N/A 

NVE BART Limit 0.40 N/A 

Current Wet Soda Ash Scrubber 0.15 or less 94+ 

Improve Existing Wet Soda Ash 

Scrubber Operation 

0.15 or less 95 

Dry Sorbent Sodium Injection 0.24 75 

New Dry FGD System 0.15 or less 90 

Furnace Sorbent Injection 0.39 60 

New Wet Lime/Limestone Scrubber 0.15 or less 95 

FGD = flue gas desulfurization 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-13 

3.2.2.3 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

When evaluating the control effectiveness of SO2 reduction technologies, each option can be 

compared against benchmarks of performance. The projected emission rate for an upgraded 

wet soda ash FGD system for Reid Gardner 3 is 95 percent SO2 removal or less than 

0.15 lb/MMBtu, while a new wet lime/limestone scrubber installation would have similar 

removal efficiency. 

Essentially the same level of SO2 reduction can be achieved through scrubber upgrades and 

new wet scrubber installation. Therefore, the new wet lime/limestone scrubber option is 

eliminated because little additional scrubber capital or operating cost is required by 

improving the current wet soda ash scrubber. 

3.2.2.4 Step 4: Evaluate Energy and Non-Air Quality Impacts 

This step involves the consideration of energy, environmental, and economic impacts 

associated with each control technology. The remaining useful life of the plant is also 

considered during the evaluation. 

Energy Impacts. Upgrading the existing wet soda ash FGD system operation will not 

require additional power. 

Environmental Impacts. There will be no environmental impacts due to improving the 

current wet soda ash scrubber operation. 

Economic Impacts. There will be no economic impacts due to improving the current wet 

soda ash scrubber operation. 

3.2.2.5 Step 5: Evaluate Visibility Impacts 

This is presented in Section 4.0, “BART Modeling Analysis.” 

3.2.3 BART PM10 Analysis 

Reid Gardner 3 is currently equipped with a mechanical collector and a venturi/tray wet 

soda ash scrubber for both particulate and SO2 control. However, as part of the planned 

environmental upgrade on Reid Gardner 3, the mechanical collector is being removed and a 

new fabric filter is being installed. 

The BART analysis for PM10 emissions at Reid Gardner 3 is described below. For the 

modeling analysis in Section 4.0, PM10 was used as an indicator for PM, and PM10 includes 

particulate matter less than 2.5 microns in aerodynamic diameter (PM2.5) as a subset. 

3.2.3.1 Step 1: Identify All Available Retrofit Control Technologies 

Three retrofit control technologies have been identified for additional PM10 control: 

• Fabric filter 

• Upgrade existing mechanical collector 

• Electrostatic precipitator 
SECTION 3.0: BART ENGINEERING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 3-14 

3.2.3.2 Step 2: Eliminate Technically Infeasible Options 

Fabric Filter. A fabric filter retrofit project is currently planned to be installed by 

July 1, 2010, on Reid Gardner 3 with guaranteed filterable particulate emissions from the 

fabric filter of 0.015 lb/MMBtu. 

Upgrade Existing Mechanical Collector. With the planned fabric filter installation, the 

mechanical collector internals will be removed to eliminate the pressure drop and allow the 

full range of particulate sizing to the fabric filter. In addition, any upgrade to the mechanical 

collector would not meet the level of emissions reduction possible with a fabric filter. 

Therefore, an upgrade of the mechanical collector is not feasible or desirable. 

New Electrostatic Precipitator. An installation of a new electrostatic precipitator is not 

justified because the potential level of emissions reduction is not as great as with the fabric 

filter installation currently planned. 

3.2.3.3 Step 3: Evaluate Control Effectiveness of Remaining Control Technologies 

The guaranteed PM10 control technology emission rate is 0.015 lb/MMBtu. 

3.2.3.4 Step 4: Evaluate Energy and Non-Air Quality Impacts 

This step involves the consideration of energy, environmental, and economic impacts 

associated with each control technology. The remaining useful life of the plant is also 

considered during the evaluation. 

Energy Impacts. While there will be additional fan horsepower to overcome pressure drop 

from a fabric filter installation, this will be more than offset by the reduction in pressure 

drop from both the venturi section of the wet scrubber and the removal of the mechanical 

collector. Therefore, a fabric filter installation is expected to result in a net energy reduction 

required for operation. 

Environmental Impacts. There are no environmental impacts expected from the installation 

of a fabric filter. 

Economic Impacts. Because the planned fabric filter project is considered to be BART, a 

comparison of technologies on the basis of costs, design control efficiencies, and tons of 

PM10 removed was not done. Cost for the fabric filter is summarized in Table 3-4. 

The complete Economic Analysis is contained in Appendix A. 

TABLE 3-4 

PM10 Control Cost 

Reid Gardner Station Unit 3 

Factor / Control Option Fabric Filter 

Total Installed Capital Costs $23.5 Million 

Total First Year Fixed and Variable O&M Costs $0.6 Million 

Total First Year Annualized Cost $3.1 Million 

3.2.3.5 Step 5: Evaluate Visibility Impacts 

This is presented in Section 4.0, BART Modeling Analysis. 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-1 

4.0 BART Modeling Analysis 

4.1 Introduction 

This section presents the dispersion modeling methods and results for estimating the degree 

of visibility improvement from BART control technology options for the NV Energy Reid 

Gardner Station Units 1, 2, and 3. 

To a large extent, the modeling followed the methodology outlined in the Western Regional 

Air Partnership (WRAP) protocol for performing BART analyses (WRAP, 2006). Any 

proposed deviations from that methodology are documented in the modeling protocol that 

is included as Appendix B to this report. 

4.2 Model Selection 

CH2M HILL used the Gaussian puff dispersion model (CALPUFF) modeling system to 

assess the visibility impacts at Class I areas. Work groups that represent the interests of the 

Federal Land Managers (FLM) recommend that an analysis of Class I area air quality and air 

quality related values (AQRVs) be performed for major sources located more than 50 km 

from these areas (EPA, 1998). The CALPUFF model is routinely recommended for these 

types of regulatory analyses. 

The CALPUFF modeling system includes the meteorological data preprocessing program 

for CALPUFF (CALMET) with algorithms for chemical transformation and deposition, and 

a post processor capable of calculating concentrations, visibility impacts, and deposition 

(CALPOST). The CALPUFF modeling system was applied in a full, refined mode. 

CH2M HILL used the latest version (Version 6) of the CALPUFF modeling system 

preprocessors and models in lieu of the EPA-approved versions (Version 5). The FLMs and 

others have noted that the EPA-approved Version 5 contained errors and that a newer 

version should be used. Consequently, it was decided to use the latest (as of April 2006) 

version of the CALPUFF modeling system (available at www.src.com): 

• CALMET Version 6.211 Level 060414 

• CALPUFF Version 6.112 Level 060412 

CALMET, CALPUFF, CALPOST, and POSTUTIL were recompiled with the Lahey/Fujitsu 

Fortran 95 Compiler (Release 7.10.02) to accommodate the large CALMET domain. The 

recompiled processors were tested against the test case results provided with the source 

code (TRC, 2007), and the difference between the results was 0.03 percent. 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-2 

4.3 CALMET Methodology 

4.3.1 Dimensions of the Modeling Domain 

CH2M HILL defined domains for Mesoscale Meteorological Model, Version 5 (MM5), 

CALMET, and CALPUFF that were slightly different than those established for the Nevada 

BART modeling in WRAP (2006). In addition, the CALMET and CALPUFF Lambert 

Conformal Conic (LCC) map projection is based on a central meridian of 117° W rather than 

97° W. This puts the central meridian near the center of the domain. 

CH2M HILL used the CALMET model to generate three-dimensional wind fields and other 

meteorological parameters suitable for use by the CALPUFF model. A CALMET modeling 

domain has been defined to allow for at least a 50-km buffer around all Class I areas within 

300 km of the Reid Gardner Power Plant. Grid resolution for this domain was 4 km. 

Figure 4-1 shows the extent of the modeling domain. 

The technical options recommended in WRAP (2006) were used for CALMET. Vertical 

resolution of the wind field included 11 layers, with vertical cell face heights as follows (in 

meters): 

• 0, 20, 100, 200, 350, 500, 750, 1000, 2000, 3000, 4000, 5000 

Also, following WRAP (2006), ZIMAX were set to 4,500 meters based on the Colorado 

Department of Health and Environment (CDPHE) analyses of soundings for summer ozone 

events in the Denver area (CDPHE, 2005). The CDPHE analysis suggests mixing heights in 

the Denver area are often well above the CALMET default value of 3,000 meters during the 

summer. For example, on some summer days, ozone levels are elevated all the way to 

6,000 meters mean sea level (MSL) or beyond during some meteorological regimes, 

including some regimes associated with high-ozone episodes. It is assumed that, as in 

Denver, mixing heights in excess of the 3,000 m AGL CALMET default maximum would 

occur in the domain used for this analysis. 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-3 

FIGURE 4-1 

Reid Gardner Power Plant, CALMET/CALPUFF Domain 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-4 

Table 4-1 lists the key user-specified options. 

TABLE 4-1 

User-Specified CALMET Options 

Description CALMET Input Parameter Value 

CALMET Input Group 2 

Map projection PMAP Lambert Conformal Conic (LCC) 

Grid spacing DGRIDKM 4 

Number vertical layers NZ 11 

Top of lowest layer (m) 20 

Top of highest layer (m) 5000 

CALMET Input Group 4 

Observation mode NOOBS 1 

CALMET Input Group 5 

Prognostic or MM-FDDA data 

switch 

IPROG 14 

Max surface over-land 

extrapolation radius (km) 

RMAX1 50 

Max aloft over-land extrapolations 

radius (km) 

RMAX2 100 

Radius of influence of terrain 

features (km) 

TERRAD 10 

Relative weight at surface of Step 1 

field and obs 

R1 100 

Relative weight aloft of Step 1 field 

and obs 

R2 200 

CALMET Input Group 6 

Maximum over-land mixing height 

(m) 

ZIMAX 4500 

4.3.2 CALMET Input Data 

CH2M HILL ran the CALMET model to produce 3 years of analysis: 2001, 2002, and 2003. 

CH2M HILL used MM5 data as the basis for the CALMET wind fields. The horizontal 

resolution of the MM5 data is 36 km. 

For 2001, CH2M HILL used MM5 data at 36-km resolution that were obtained from the 

contractor (Alpine Geophysics) who developed the nationwide data for the EPA. For 2002, 

CH2M HILL used 36-km MM5 data obtained from Alpine Geophysics, originally developed 

for the WRAP. Data for 2003 (also from Alpine Geophysics), at 36-km resolution, were 

developed by the Wisconsin Department of Natural Resources, the Illinois Environmental 

Protection Agency, and the Lake Michigan Air Directors Consortium (Midwest RPO). 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-5 

The MM5 data were used as input to CALMET as the “initial guess” wind field. The initial 

guess field was adjusted by CALMET for local terrain and land use effects to generate a 

Step 1 wind field, and then further refined using local surface observations to create a final 

Step 2 wind field. 

Surface data for 2001-2003 were obtained from the National Climatic Data Center (NCDC). 

CH2M HILL processed data for all stations from the National Weather Service’s (NWS) 

Automated Surface Observing System (ASOS) network that are in the domain. The surface 

data were obtained in abbreviated DATSAV3 format. A conversion routine available from 

the TRC website was used to convert the DATSAV3 files to CD 144 format for input to the 

SMERGE preprocessor and CALMET. 

Land use and terrain data were obtained from the U.S. Geological Survey (USGS). Land use 

data were obtained in Composite Theme Grid (CTG) format from the USGS, and the Level I 

USGS land use categories were mapped into the 14 primary CALMET land use categories. 

Surface properties, such as albedo, Bowen ratio, roughness length, and leaf area index, were 

computed from the land use values. Terrain data were taken from USGS 1 degree Digital 

Elevation Model (DEM) data, which are primarily derived from USGS 1:250,000 scale 

topographic maps. Missing land use data were filled with a value that is appropriate for the 

missing area. 

Precipitation data were ordered from the NCDC. All available data in fixed-length, TD-3240 

format were ordered for the modeling domain. The list of available stations and stations that 

have collected complete data varies by year, but CH2M HILL processed all available 

stations/data within the domain for each year. Precipitation data were prepared with the 

PXTRACT/PMERGE processors in preparation for use within CALMET. 

Following the methodology recommended in WRAP (2006), no observed upper-air 

meteorological observations were used as they are redundant to the MM5 data and may 

introduce spurious artifacts in the wind fields. In the development of the MM5 data, the 

twice daily upper-air meteorological observations were used as input with the MM5 model. 

The MM5 estimates were nudged to the upper-air observations as part of the Four 

Dimensional Data Assimilation (FDDA). This results in higher temporal (hourly vs. 12 hour) 

and spatial (36 km vs. ~300 km) resolution for the upper-air meteorology in the MM5 field. 

These MM5 data are more dynamically balanced than those contained in the upper-air 

observations. Therefore, the use of the upper-air observations with CALMET is not needed, 

and, in fact, will upset the dynamic balance of the meteorological fields potentially 

producing spurious vertical velocities. 

4.3.3 Validation of CALMET Wind Field 

CH2M HILL used the CalDESK (program to display data and results) data display and 

analysis system (v2.97, Enviromodeling Ltda.) to view plots of wind vectors and other 

meteorological parameters to evaluate the CALMET wind fields. We used observed weather 

conditions, as depicted in surface and upper-air weather maps from the National Oceanic 

and Atmospheric Administration (NOAA) Central Library U.S. Daily Weather Maps Project 

(http://docs.lib.noaa.gov/rescue/dwm/data_rescue_daily_weather_maps.html), to 

compare to the CalDESK displays. 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-6 

4.4 CALPUFF Methodology 

4.4.1 CALPUFF Modeling 

CH2M HILL ran the CALPUFF model with the meteorological output from CALMET over 

the CALPUFF modeling domain (Figure 4-1). The CALPUFF model was used to predict 

visibility impacts for the pre-control (baseline) scenario for comparison to the predicted 

impacts for post-control scenarios. 

4.4.1.1 Background Ozone and Ammonia 

Hourly values of background ozone concentrations were used by CALPUFF for the 

calculation of SO2 and NOX transformation with the MESOPUFF II chemical transformation 

scheme. CH2M HILL used the hourly ozone data generated for the WRAP BART analysis 

for 2001, 2002, and 2003. 

For periods of missing hourly ozone data, the chemical transformation relied on a monthly 

default value of 80 parts per billion (ppb). Background ammonia was set to 1 ppb as 

recommended in WRAP (2006). 

4.4.1.2 Stack Parameters 

The baseline stack parameters for the baseline and post-control scenarios were the same as 

those used the WRAP Regional Modeling Center (RMC) analyses. None of the emission 

controls included in this BART analysis would substantially affect the exhaust exit flows or 

temperatures. 

4.4.1.3 Pre-Control Emission Rates 

Pre-control emission rates reflect normal maximum capacity 24-hour emissions that may 

occur under the source’s current permit. The emission rates reflect actual emissions under 

normal operating conditions. As described by the EPA in the Regional Haze Regulations 

and Guidelines for BART Determinations; Final Rule (40 CFR Part 51; July 6, 2005, pg. 9129): 

“The emissions estimates used in the models are intended to reflect steady-state 

operating conditions during periods of high-capacity utilization. We do not generally 

recommend that emissions reflecting periods of start-up, shutdown, and malfunction 

be used...” 

CH2M HILL selected the emissions rates used in the WRAP RMC modeling as the Precontrol (baseline) emission rates. The WRAP PM10 and SO2 were speciated to determine 

emission rates for coarse particulate, fine particulate, elemental carbon, organic aerosols, 

and sulfates. 

Emissions were modeled for the following species: 

• Sulfur dioxide (SO2) 

• Nitrogen oxides (NOx) 

• Coarse particulate (PM2.5 < diameter ≤ PM10) 

• Fine particulate (diameter ≤ PM2.5) 

• Elemental carbon (EC) 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-7 

• Organic aerosols (SOA) 

• Sulfates (SO4) 

4.4.1.4 Post-control Emission Rates 

Post-control emission rates represent the NV Energy BART Limit emission levels presented 

in Table 5-1, with the exception of the NOx and PM10 emission rate which are in excess of the 

NVEBL. 

4.4.1.5 Modeling Process 

The CALPUFF modeling for the control technology options followed this sequence: 

• Model WRAP-RMC parameters to verify results 

• Model Title V Permit Limits 

Model Scenario 1 (NVE BART Limit) emissions, with the exception of the NOx and 

PM10emission rate which are in excess of the NVEBL. 

• Determine the degree of visibility improvement 

4.4.2 Receptor Grids and Coordinate Conversion 

The TRC COORDS program was used to convert the latitude/longitude coordinates to LCC 

coordinates for the meteorological stations and source locations. The USGS conversion 

program PROJ (version 4.4.6) was used to convert the National Park Service (NPS) receptor 

location data from latitude/longitude to LCC. 

For the Class I areas that are within 300 km of the Reid Gardner Power Plant, discrete 

receptors for the CALPUFF modeling were taken from the NPS database for Class I area 

modeling receptors. The entire area of each Class I area that is within or intersects the 

300-km circle (Figure 3-1) were included in the modeling analysis. The following lists the 

Class I areas that were modeled for the Reid Gardner facility: 

• Bryce Canyon National Park (NP) (Brca) 

• Grand Canyon NP (Grca) 

• Joshua Tree NM (Jotr) 

• Sycamore Canyon Wilderness (Syca) 

• Zion NP (Zion) 

4.5 Visibility Post-processing 

4.5.1 CALPOST 

The CALPOST processor was used to determine 24-hour average visibility results. Output is 

specified in deciview (dv) units. 

Calculations of light extinction were made for each pollutant modeled. The sum of all 

extinction values was used to calculate the delta-dv (∆dv) change relative to natural 

background. Default extinction coefficients for each species, as shown below, were used: 

• Ammonium sulfate 3.0 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-8 

• Ammonium nitrate 3.0 

• PM coarse (PM10) 0.6 

• PM fine (PM2.5) 1.0 

• Organic carbon 4.0 

• Elemental carbon 10.0 

CALPOST visibility Method 6 (MVISBK=6) was used for the determination of visibility 

impacts. Monthly average relative humidity factors [f(RH)] were used in the light extinction 

calculations to account for the hygroscopic characteristic of sulfate and nitrate particles. 

Monthly f(RH) values, from the WRAP_RMC BART modeling, were used in CALPOST for 

the particular Class I area being modeled. 

The natural background conditions used in the post-processing to determine the change in 

visual range background - or delta-deciview (∆dv) - represent the average natural 

background concentration for western Class I areas. 

Table 4-2 lists the annual average species concentrations from the EPA Guidance. 

TABLE 4-2 

Average Natural Levels of Aerosol Components 

Aerosol Component Average Natural Concentration (μg/m3) for Western Class I Areas 

Ammonium Sulfate 0.12 

Ammonium Nitrate 0.10 

Organic Carbon 0.47 

Elemental Carbon 0.02 

Soil 0.50 

Coarse Mass 3.0 

Note: Taken from Table 2-1 of Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

Rule. EPA-454/B-03-005, September 2003. 

4.6 Results 

Input and output files for the CALMET/CALPUFF modeling and post-processing will be 

provided upon request. 

4.6.1 WRAP Verification Runs Results 

Tables 4-3 and 4-4 present the results of WRAP-RMC model verification runs. Except for the 

results at Joshua Tree NP, the results show good correlation in estimated maximum ∆dv. 

Much of the difference between these values is probably attributed to the different 

alignment of the LCC grids (reference discussion in Section 4.3.1). 
SECTION 4.0: BART MODELING ANALYSIS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 4-9 

TABLE 4-3 

Results from WRAP-RMC CALPUFF Modeling for Reid Gardner Boilers 1, 2, and 3 (WRAP 2007) 

98th Percentile ∆dv for Each Year 

Class I 

Area 

Min Distance 

(km) 

Max Delta 

∆dv 

98th Percentile 

∆dv 

Days > 

0.5 ∆dv 2001 2002 2003 

98th ∆dv 

3-year Avg 

Grca 85 3.61 1.11 60 1.72 1.03 1.00 1.25 

Zion 148 2.44 0.73 38 0.83 0.46 0.74 0.68 

Brca 226 1.27 0.29 8 0.29 0.21 0.37 0.29 

Syca 288 0.73 0.18 4 0.19 0.17 0.14 0.17 

Jotr 292 1.56 0.70 48 0.88 0.56 0.55 0.67 

TABLE 4-4 

Verification CALPUFF Modeling Results 

98th Percentile ∆dv for Each Year 

Class I 

Area 

Min Distance 

(km) 

Max Delta 

∆dv 

98th Percentile 

∆dv 

Days > 

0.5 ∆dv 2001 2002 2003 

98th ∆dv 

3-year Avg 

Grca 86 3.76 1.94 47 1.83 1.93 1.94 1.90 

Zion 148 2.14 0.58 14 0.55 0.45 0.80 0.60 

Brca 227 1.16 0.36 5 0.39 0.24 0.38 0.34 

Syca 289 0.61 0.18 2 0.14 0.18 0.23 0.18 

Jotr 292 1.92 0.86 32 1.04 0.85 0.58 0.82 

4.6.2 BART Modeling Analysis 

The results and comparisons of the CALPUFF modeling for the baseline emission rates and 

those for the NVE BART Limit emission rates are provided in Section 5. As previously 

mentioned, the NOx and PM10 emission rates modeled are in excess of the NVEBL. 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 5-1 

5.0 BART Analysis and Recommendations 

5.1 Recommended BART Controls 

As a result of the completed technical and economic evaluations, and consideration of the 

modeling analysis for Reid Gardner 3, the recommended BART controls for NOx, SO2, and 

PM10 are as follows: 

• LNB with OFA for NOx control 

• Continued wet soda ash FGD operation for SO2 control 

• Fabric filter for PM10 control 

Table 5-1 compares the baseline emission control scenario with expected emission levels 

utilizing the NVE BART Limit emission levels. Because of the basis utilized to establish the 

estimated emissions rate for each of these cases, it is important to consider economic and 

dispersion modeling results for each scenario in making the overall BART recommendation. 

The WRAP baseline represents a snap-shot view of emissions based upon the year 2006, and 

does not necessarily represent worst case potential emission rates. While the NOx emission 

rate modeled is in excess of the current NVEBL, modeling results represent worst case 

visibility impacts. The Title V permit limit offers a more representative view of maximum 

potential emission rates, since these are enforceable operating limits. 

Comparison of dispersion modeling results for the three scenarios are presented below. 

TABLE 5-1 

Modeled Emission Control Scenarios 

Reid Gardner Station Unit 3

Case 

Expected NOx 

Emissions 

(lb/MMBtu) 

Expected SO2 

Emissions 

(lb/MMBtu) 

Expected PM10 

Emissions 

(lb/MMBtu) 

WRAP Baseline 0.592 0.320 0.040 

Title V Emission Limit Baseline 0.46 0.55 0.1 

Scenario 1 – NVE BART Limita 0.46 0.40 0.03 

a

 – NOx and PM10 emission rates higher than NVEBL

The ranking of the different NOx emission control scenarios based on annual costs, from 

lowest to highest cost, is presented on Table 5-2. 
SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 5-2 

TABLE 5-2 

Ranking of NOx Control Scenarios by Cost 

Reid Gardner Station Unit 3

Rank Controls Total Annual Cost 

1 LNB w/OFA $0.6 Million 

2 New LNB w/OFA and SNCR $1.1 Million 

3 ROFA w/Rotamix $1.4 Million 

4 New LNB w/OFA and SCR $4.7 Million 

5 ROFA w/SCR $5.4 Million 

5.2 Dispersion Modeling Results 

The results of the dispersion modeling are shown below. In this analysis the WRAP 

emission rates are used as a historical baseline. Table 5-3 compares visibility impacts of the 

WRAP baseline, the current Title V permit limits and the NVE BART Limit emission rates. 

The NVE BART Limit emission rates for Reid Gardner Unit 3 demonstrate an improvement 

in visibility. 

TABLE 5-3 

Comparison of Visibility Impacts by Class I Area 

Reid Gardner Unit 3 

98th Percentile ∆dv Number of Days Exceeding 0.5 ∆dv

Area 

Distance 

(km) 

WRAP 

Baseline 

Title V 

Permit Limit 

NVE BART 

Limit 

WRAP 

Baseline 

Title V 

Permit Limit 

NVE BART 

Limit 

Grca 86 0.79 0.82 0.73 17 18 18 

Zion 148 0.22 0.23 0.20 3 4 2 

Brca 227 0.13 0.15 0.13 0 0 0 

Syca 289 0.07 0.08 0.07 0 0 0 

Jotr 292 0.33 0.40 0.34 3 7 4 
SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 5-3 

FIGURE 5-1 

Comparison of 98th Percentile Delta Deciview Visibility Impacts 

Reid Gardner 3 

Comparison of 98th Percentile Delta Deciview Visibility Impacts

Reid Gardner Unit 3

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

Grand Canyon NP Zion NP Bryce Canyon NP Sycamore Canyon W Joshua Tree NP

Class I Area

Delta Deciview

WRAP Basline

Title V Permit Limit

SPR BART Limit
SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 5-4 

FIGURE5-2 

Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv

Reid Gardner 3 

Comparison of Days of Visibility Impacts Exceeding 0.5 ∆dv

Reid Gardner Unit 3

0

2

4

6

8

10

12

14

16

18

20

Grand Canyon NP Zion NP Bryce Canyon NP Sycamore Canyon W Joshua Tree NP

Class I Area

Days

WRAP Baseline

Title V Permit Limit

SPR BART Limit

As shown in Figures 5-1 through 5-2, there is a decrease in modeled visibility impact when 

reducing the modeled emission levels from the Title V Permit Limit to the NVEBL emission 

rates. The modeled visibility impact from the modeled emission levels from the WRAP and 

NVEBL are similar. 

NOx Control Scenario Visibility Modeling 

While visibility modeling has not been completed for the combination of NOx, SO2, and 

PM10 NBEBL values, Table 5-4 below compares the results for the various NOx control 

technologies. Results from one representative Class I area is provided. 

Based on an evaluation of the cost per ∆dv reduction from Table 5-4, LNB with OFA is 

selected as BART for Reid Gardner 3. 
SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 5-5 

TABLE 5-4 

Control Scenario Results for the Grand Canyon National Park 

Reid Gardner 3 

Scenario Controls 

Average 

Number 

of Days 

Above 

0.5 ∆dV 

(Days) 

98th 

Percentile 

∆dV 

Reduction 

Total 

Annualized 

Cost 

(Million$) 

Cost per 

∆dV 

Reduction 

(Million$/dV 

Reduced) 

Base 5 0.386 0 0 

1 LNB w/OFA 5 0.407 0.552 1.356 

2 

LNB w/OFA and 

SNCR 3 0.485 1.083 2.232 

3 ROFA w/Rotamix 3 0.514 1.380 2.684 

4 ROFA w/SCR 0 0.652 4.718 7.236 

5 LNB w/OFA and SCR 0 0.652 5.402 8.285 

5.3 Recommendations 

5.3.1 NOx Emission Control 

LNB with OFA has been selected as the NOx reduction technology with a NVE BART Limit 

(NVEBL) of 0.39 lb/MMBtu averaged on an annual basis. . A unit specific engineering 

analysis will be performed to determine the required operational and technology options to 

achieve the NVEBL. 

Due to uncertainties in future coal supply, and changes in boiler operation from the current 

pressurized operation to balanced draft operation, the NVEBL of 0.39 lb/MMBtu on an 

annual basis was established. 

5.3.2 SO2 Emission Control 

The use of the existing wet soda ash FGD system with a NVE BART limit of 0.40 lb/MMBtu 

averaged on a 24-hour basis is selected as BART for Reid Gardner 3. Although no scrubber 

upgrades are required to meet the NVE BART Limit, improved operation is anticipated due 

to the currently planned fabric filter installation. . A unit specific engineering analysis will 

be performed to determine the required operational and technology options to achieve the 

NVEBL. 
SECTION 5.0: PRELIMINARY ASSESSMENT AND RECOMMENDATIONS 

DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 5-6 

5.3.3 PM10 Emission Control 

A fabric filter is considered BART for Reid Gardner 3 based on its reduction in PM10

emissions with a NVE BART Limit of 0.02 lb/MMBtu averaged on a 3-hour basis. A unit 

specific engineering analysis will be performed to determine the required operational and 

technology options to achieve the NVEBL. 

5.4 Just-Noticeable Differences in Atmospheric Haze

Conclusions reached in the reference document Just-Noticeable Differences in Atmospheric 

Haze by Dr. Ronald Henry of the University of Southern California, state that only dV 

differences of approximately 1.5 to 2.0 dV, or more are perceivable by the human eye. 

Deciview changes of less than 1.5 cannot be distinguished by the average person. Therefore, 

the modeling analysis results indicate that only minimal, if any, observable visibility 

improvements at the Class I areas studied would be expected under any of the scenarios. 

Thus the results indicate that even though many millions of dollars will be spent, only 

minimal, if any, noticeable visibility improvements may result. 

Finally, it should be noted that none of the data were corrected for natural obscuration 

where water in various forms (fog, clouds, snow, or rain) or other naturally caused aerosols 

obscure the atmosphere. During the period of 2001 through 2003, there were several megawildfires that lasted for many days and could have had a major impact of background 

visibility in these Class I areas. If natural obscuration were to reduce the reduction in 

visibility impacts modeled for the Reid Gardner facility, the effect would be to increase the 

costs per ∆dV reduction that are presented in this report. 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 6-1 

6.0 References 

40 CFR Part 51. 2005. Regional Haze Regulations and Guidelines for Best Available Retrofit 

Technology Determinations; Final Rule (July 6, 2005, pg 39129). 

United States Environmental Protection Agency. 1990. New Source Review Workshop Manual –

Prevention of Significant Deterioration and Nonattainment Area Permitting. October 1990. 

EPA. 1998. Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Summary Report 

and Recommendations for Modeling Long-Range Transport Impacts. Air Quality Modeling Group 

(MD-14), Research Triangle Park, North Carolina; National Park Service, Air Resources 

Division, Denver, Colorado; USDA Forest Service, Air Program, Fort Collins, Colorado; and 

U.S. Fish and Wildlife Service, Air Quality Branch, Denver, Colorado. December 1998. 

Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Rule. 

Henry, Ronald C. 2002. “Just-Noticeable Differences in Atmospheric Haze.” Journal of the Air 

and Waste Management Association 52:1238-1243. October 2002 

Western Regional Air Partnership (WRAP). 2007. Summary of WRAP RMC BART Modeling 

for Nevada, Draft#8. May 14, 2007. 

WRAP. 2006. Draft Final Modeling Protocol, CALMET/CALPUFF Protocol for BART Exemption 

Screening Analysis for Class I Areas in the Western United States. Air Quality Modeling Forum. 

Regional Modeling Center. August 15, 2006. 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 

Appendices 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 

APPENDIX A 

Economic Analysis 
DEN/ES072007003/REID_GARDNER_3_10-03-08.DOC 

APPENDIX B 

BART Protocol